INVESTOR UPDATE. September 2016

Transcription

1 INVESTOR UPDATE September 2016

2 FORWARD-LOOKING STATEMENTS Statements contained in this presentation that include company expectations or predictions should be considered forward-looking statements that are covered by the safe harbor protections provided under federal securities legislation and other applicable laws. It is important to note that the actual results could differ materially from those projected in such forwardlooking statements. For additional information that could cause actual results to differ materially from such forward-looking statements, refer to ONEOK s and ONEOK Partners Securities and Exchange Commission filings. This presentation contains factual business information or forward-looking information and is neither an offer to sell nor a solicitation of an offer to buy any securities of ONEOK or ONEOK Partners. All references in this presentation to financial guidance are based on news releases issued on Dec. 21, 2015, Feb. 22, 2016, May 3, 2016, and Aug. 2, 2016, and are not being updated or affirmed by this presentation. Page 2

3 INDEX ONEOK Overview 4 ONEOK Partners Overview 6 ONEOK Partners Business Segments Natural Gas Liquids 13 Natural Gas Gathering and Processing 19 Natural Gas Pipelines 23 Financial Strength 28 Appendix Natural Gas Gathering and Processing 34 ONEOK Non-GAAP Reconciliations 40 ONEOK Partners Non-GAAP Reconciliations 44 Page 3

4 ONEOK OVERVIEW

5 OKS GROWTH BENEFITS OKE VALUE OF GP INTEREST TO ONEOK ONEOK Partners completed capital-growth projects and strategic acquisitions expected to drive distribution growth Nearly 70% of every incremental ONEOK Partners adjusted EBITDA dollar, at current ownership level, flows to ONEOK as ONEOK Partners distributions ONEOK s excess cash can support ONEOK Partners, if needed $344 $200 $144 Distributions Declared to ONEOK ($ in Millions) $476 $250 $226 18% CAGR $546 $268 $278 $285 $348 $327 $360 $408 $ G GP interest $633 $735 LP interest $790 Page 5

6 ONEOK PARTNERS OVERVIEW

7 ONEOK PARTNERS GEOGRAPHICALLY DIVERSE ASSETS Owns and operates strategically located assets in midstream natural gas liquids and natural gas businesses Provides nondiscretionary services to producers, processors and customers Extensive 37,000-mile integrated network of natural gas liquids and natural gas pipelines Supply and market diversity create opportunities Natural Gas Liquids Natural Gas Pipelines Natural Gas Gathering & Processing Page 7

8 OKS GROWTH: COMPLETED ~$9 BILLION OF GROWTH PROJECTS AND ACQUISITIONS 2. Niobrara/Powder River Basin Niobrara NGL Lateral OPPL Expansion Sage Creek and NGL Infrastructure Acquisition Bakken/Williston Basin Plants: Garden Creek I, II and III; Grasslands Plant Expansion; Stateline I and II; Lonesome Creek; and Bear Creek Bakken NGL Pipeline and Expansion Phase I Field Compression and Related Infrastructure Divide County Gathering System Related NGL Infrastructure 4. Permian Basin and Gulf Coast Roadrunner Gas Transmission Pipeline Sterling I Expansion Sterling I and II Reconfiguration Sterling III and Arbuckle Pipelines MB II and III Fractionators Mont Belvieu E/P Splitter Ethane Header Pipeline West Texas LPG Pipeline System Acquisition WesTex Transmission Pipeline Expansion Natural Gas Gathering & Processing Natural Gas Liquids Natural Gas Pipelines Completed Growth Projects and Acquisitions Midwest Region MGT/Compressor Station Midwestern Extension Guardian II Expansion North System Acquisition 5. Mid-Continent Region Canadian Valley Plant NGL Plant Connections Bushton Fractionator Expansion NGL Pipeline and Hutchinson Fractionator Infrastructure Maysville Plant Acquisition Page 8

9 ONEOK PARTNERS SOURCES OF EARNINGS TRANSFORMED TO MORE FEE BASED Volume risk Exists primarily in natural gas gathering and processing and natural gas liquids segments Ethane opportunity impacts the natural gas liquids segment Mitigated by supply and market diversity, firm-based, frac-or-pay and ship-or-pay contracts Mitigated by significant acreage dedications in the core areas of the basins we operate in Commodity price risk significantly reduced Recontracting efforts increased fee-based earnings and decreased commodity exposure Remaining commodity exposure mitigated by hedging Price differential risk NGL location price differentials between Mid-Continent and Gulf Coast and product price differentials Optimization expected to be less of a contributor Assets can be utilized to capture location and product price differentials $1.6 B $1.7 B $2.1 B $2.1 B ~ $2.5 B 11% 5% ~ 5% 12% 20% 12% ~ 10% 22% 58% Sources of Earnings ($ in billions) 23% 22% 66% 66% 83% ~ 85% G Fee Commodity Differential Page 9

10 ONEOK PARTNERS UNIQUELY POSITIONED TO CREATE LONG-TERM VALUE Increasing fee-based earnings through gathering, processing, fractionation, storage and transport services ONEOK Partners fee-based earnings are expected to increase to more than 85% in 2016 from approximately 66% in 2014 Market driven projects continue to emerge NGL and natural gas Natural gas exports to Mexico driven by growing demand Ethane demand projected to significantly increase due to petrochemical facilities Lower natural gas prices could stimulate more ethane recovery Supply and market diversification strategic, integrated assets in growing NGL-rich plays and wellpositioned in major market areas NGL-rich plays: Williston, Powder River, Mid-Continent and Permian Major markets: Gulf Coast, Midwest and Southwest Supply backlog in core areas of the Williston Basin Large backlog of drilled but uncompleted wells Recent compression infrastructure, Lonesome Creek and Bear Creek plants capture flared gas inventory Continued drilling in most productive areas Strong, investment-grade balance sheet, liquidity and financial flexibility as a result of disciplined growth and prudent financial actions Page 10

11 Page 11 OUR KEY STRATEGIES A PREMIER ENERGY COMPANY GROWTH Increase distributable cash flow through investments in organic growth projects and strategic acquisitions Continue to increase NGL and natural gas volume Continue to grow/expand our integrated natural gas liquids and natural gas infrastructure by utilizing our strategic supply and market positions Continue to increase fee-based earnings in all three business segments FINANCIAL Proactively manage balance sheet and maintain investment-grade credit ratings at ONEOK Partners Manage capital spending and distribution growth rates over the long term, resulting in financial strength Continue to take necessary steps to maintain investment-grade credit rating ENVIRONMENT, SAFETY AND HEALTH Continue sustainable improvement in ESH performance Continue to maintain the mechanical reliability of our assets PEOPLE Attract, select, develop, motivate, challenge and retain a diverse and inclusive group of employees to support strategy execution Management continuity is the result of effective succession planning

12 ONEOK PARTNERS BUSINESS SEGMENTS

13 NATURAL GAS LIQUIDS

14 NATURAL GAS LIQUIDS ASSET OVERVIEW Provides nondiscretionary, fee-based services to natural gas processors and customers Gathering, fractionation, transportation, marketing and storage Extensive NGL gathering system Second largest in the U.S. Connected to more than 180 natural gas processing plants in the Mid-Continent, Barnett Shale, Rocky Mountain regions and Permian Basin Represents 90% of pipeline-connected natural gas processing plants located in Mid-Continent Well positioned to capture growth in SCOOP/STACK and Cana-Woodford Contracted NGL volumes exceed physical volumes minimum volume commitments Extensive NGL fractionation system Second largest in the U.S. Page 14 Fractionation capacity near two market hubs Conway, KS and Medford, OK 500,000 bpd capacity Mont Belvieu, TX 340,000 bpd capacity Bakken NGL Pipeline offers exclusive pipeline takeaway from the Williston Basin Links key NGL market centers at Conway, Kansas, and Mont Belvieu, Texas North System supplies Midwest refineries and propane markets Fractionation Isomerization E/P Splitter Storage Distribution Gathering Raw Feed 840,000 bpd net capacity 9,000 bpd capacity 40,000 bpd 26.7 MMBbl capacity 4,380 miles of pipe with 1,060 mbpd capacity 7,090 miles of pipe with 1,480 MBpd capacity As of Dec. 31, 2015 NGL Gathering Pipelines NGL Distribution Pipelines NGL Market Hub NGL Fractionator Overland Pass Pipeline (50% interest) NGL Storage

15 NATURAL GAS LIQUIDS PREDOMINANTLY FEE BASED Exchange Services - Primarily fee based Gather, fractionate and transport raw NGL feed to storage and market hubs Transportation & Storage Services - Fee based Transport NGL products to market centers and provide storage services for NGL products Marketing - Differential based Purchase for resale approximately 70% of fractionator supply on an index-related basis and truck and rail services Optimization - Differential based Obtain highest product price by directing product movement between market hubs and convert normal butane to iso-butane 47% 12% 7% 34% 70% 69% 78% ~ 78% 15% 8% 12% 9% 7% 10% 12% ~ 12% 5% ~ 5% 5% ~ 5% G Focused on increasing fee-based exchange-services earnings Exchange Services Transportation & Storage Marketing Optimization Page 15

16 NATURAL GAS LIQUIDS VOLUME UPDATE Approximately one-third of all U.S. ethane being rejected is on ONEOK Partners NGL system Potential annual earnings uplift from full ethane recovery estimated to be approximately $200 million 2016 volume growth weighted toward the second half of the year Second-quarter gathered volumes increased 8%, and fractionated volumes increased 11% compared with the first quarter 2016 Six new processing plants connected in Gathered Volume (MBbl/d) G Gathered Volume Ethane Opportunity Fractionation Volume (MBbl/d) Region/ Asset Second Quarter 2016 Average Gathered Volumes Average Bundled Rate (per gallon) Bakken NGL Pipeline 123,000 bpd > 30 cents** Mid-Continent 484,000* bpd < 9 cents** Page 16 West Texas LPG system * Includes spot volumes ** Includes transportation and fractionation *** Includes transportation 202,000 bpd < 3 cents*** G Fractionation Ethane Opportunity

17 ETHANE RECOVERY BY BASIN INCREMENTAL ETHANE DEMAND CAPACITY Approximately one-third of all U.S. ethane being rejected is on ONEOK Partners NGL system ONEOK Partners NGL infrastructure already connects supply to Gulf Coast region Incremental ethane transported and fractionated volume potential of 175, ,000 bpd Potential annual earnings uplift from full ethane recovery estimated to be approximately $200 million Basins closer to market hubs will likely be the first to recover ethane Incremental ethane opportunity for the partnership by basin: Ethane Supply Mid-Continent: ~140,000 bpd Williston Basin: ~35,000 bpd Permian: ~10,000 bpd Expected Timing Expected Incremental Petrochemical and Export Capacity* 1 2Q2016 1Q ,000 bpd 2 2Q2017 3Q ,000 bpd 3 4Q2017 1Q ,000 bpd Total 863,000 bpd Permian Basin 1 Williston Basin/ Rockies 2 3 Eagle Ford Shale 1 Mid-Continent 1 2 Appalachia 2 3 Page 17 * As of June 30, 2016 ONEOK Partners NGL assets

18 STACK AND SCOOP PLAYS POSITIONED AS A CRITICAL NGL TAKEAWAY PROVIDER Approximately 140,000 bpd of ethane opportunity on our NGL system ~110 third-party plant connections in the Mid-Continent Expect incremental 100,000 bpd of NGLs gathered from the STACK and SCOOP plays NGL Gathering Pipelines NGL Distribution Pipelines Page 18

19 NATURAL GAS GATHERING AND PROCESSING

20 NATURAL GAS GATHERING AND PROCESSING ASSET OVERVIEW Page 20 Nondiscretionary services to producers Gathering, compression, treating and processing Diverse contract portfolio More than 2,000 contracts Percent of proceeds (POP) with fees Restructured significant POP with fee contracts to include a larger fee component Natural gas supplies from three core areas: Williston Basin Includes oil, natural gas and natural gas liquids in the Bakken and Three Forks formations Mid-Continent STACK* SCOOP** Cana-Woodford Shale Mississippian Lime Granite Wash, Hugoton, Central Kansas Uplift Powder River Basin Crude oil and NGL-rich Niobrara, Sussex and Turner formations *Sooner Trend (oil field), Anadarko (basin), Canadian and Kingfisher (counties) **South Central Oklahoma Oil Province Gathering Processing Production 18,800 miles of pipe Powder River Basin Gathering pipelines Natural gas processing plant 21 active plants (including Bear Creek) 1,830 MMcf/d capacity Niobrara Shale 1,930 BBtu/d or 1,524 MMcf/d gathered 1,690 BBtu/d or 1,280 MMcf/d processed; 850 BBtu/d residue gas sold 130 MBbl/d NGLs sold Production as of Dec. 31, 2015 Williston Basin STACK Cana-Woodford SCOOP

21 NATURAL GAS GATHERING AND PROCESSING PRIMARILY FEE BASED Achieving increased fee-based contract mix by restructuring percent-of-proceeds (POP) contracts with a fee component to include a higher fee rate Increasing fee-based earnings while providing enhanced services to customers Restructuring efforts continue to be successful and are ongoing Average Fee Rate Contract Mix by Earnings 95% increase Q Q % 66% 67% 44% <25% $0.39 $0.43 $0.55 $0.68 $ % 34% 33% 56% >75% Q Q Q Q Q Average Fee Rate per MMBtu G Fee Based Commodity Page 21

22 Page 22 NATURAL GAS GATHERING AND PROCESSING VOLUME UPDATE Mid-Continent STACK/SCOOP production continues to increase Initial production (IP) rates higher than other areas Well completions expected to increase beginning in late Q More than 60 percent of total Oklahoma rigs located in STACK/SCOOP plays as of June 2016 Rocky Mountain Bear Creek plant and related infrastructure completed in August 2016 Expected to capture MMcf/d of natural gas currently flaring Region Second Quarter 2016 Average Gathered Volumes Second Quarter 2016 Average Processed Volumes Rocky Mountain 793 MMcf/d 759 MMcf/d Mid-Continent 774 MMcf/d 646 MMcf/d Note: For full year comparison, 2015 quarterly gathered and processed volumes are included on slide 38. 1, Gathered Volumes (MMcf/d) 1, ,700 1, , G 1, Processed Volumes (MMcf/d) 1, ,500 1, G Rocky Mountain Mid-Continent

23 NATURAL GAS PIPELINES

24 NATURAL GAS PIPELINES ASSET OVERVIEW Predominantly fee-based income 92% of transportation capacity contracted under firm demand-based rates in % of contracted system transportation capacity serves end-use markets in 2015 Connected directly to end-use markets Local natural gas distribution companies Electric-generation facilities Large industrial companies 71% of storage capacity contracted under firm, fee-based arrangements in 2015 Pipelines Storage 6,610 miles, 6.4 Bcf/d peak capacity 55.4 Bcf active working capacity As of Dec. 31, 2015 Natural Gas Interstate Pipeline Natural Gas Intrastate Pipeline Natural Gas Storage Northern Border Pipeline (50% interest) Roadrunner Gas Transmission (50% interest) Page 24

25 NATURAL GAS PIPELINES PREDOMINANTLY FEE BASED Nearly 100% of earnings is firm, fee-based Firm demand-based contracts serving primarily investment-grade utility customers Sources of Earnings 6% 4% 8% 2% ~ 4% Roadrunner Gas Transmission pipeline project and WesTex pipeline expansion to enhance export capability to Mexico Phase I completed in March 2016 Phase II expected completion in the fourth quarter 2016 Contract terms of 25 years* 94% 96% 92% 98% ~ 96% Fee-based earnings further enhanced with the completion of a natural gas compressor station project on Midwestern Gas Transmission in March G Fee Based Commodity *Subject to satisfaction of certain precedent conditions Page 25

26 NATURAL GAS PIPELINES SERVING MOSTLY INVESTMENT GRADE UTILITIES 2016 Percent of Revenues From Firm, Fee Contracts* Roadrunner Gas Transmission** Guardian Pipeline Viking Gas Transmission Northern Border** Midwestern Gas Transmission ONEOK Gas Transmission ONEOK WesTex Transmission ~ 100% ~ 98% ~ 97% ~ 95% ~ 95% ~ 89% ~ 83% 0% 20% 40% 60% 80% 100% 2016 Largest Pipeline Customers* AGL Resources Atmos Energy Comisión Federal de Electricidad*** Exelon OGE Energy ONE Gas Piedmont Natural Gas Company WEC Energy Group Western Farmers Electric Cooperative XCEL Energy Page 26 * As of June 30, 2016 **50-50 joint venture equity method investment ***Largest customer for ONEOK Partners Roadrunner Gas Transmission joint venture equity method investment

27 Revenue ($ millions) Storage Subscribed NATURAL GAS PIPELINES STORAGE REVENUE AND CAPACITY Revenues have remained stable, despite a decrease in contracted storage capacity since 2012 Customers are paying increased rates for deliverability $85 $70 $73.5 $78.7 $81.4 $ % 80% $55 60% 40% $40 20% $ Revenue* Storage Subscribed 0% Page 27 *Includes intercompany and transportation revenues associated with storage services

28 FINANCIAL STRENGTH

29 STRONG BALANCE SHEETS COMMITTED TO OKS INVESTMENT-GRADE CREDIT RATING ONEOK Partners Capital structure targets 50/50 capitalization Debt-to-Adjusted EBITDA ratio < 4.0x Committed to taking necessary steps to keep investment-grade credit ratings S&P: BBB (negative) Moody s: Baa2 (negative) $2.4 billion revolving credit facility Matures 2020 $1 billion three-year term loan ONEOK Pre-payable in whole or in part Two one-year extensions $300 million revolving credit facility Matures 2020 Significant free cash flow at OKE available to support OKS, if needed Expect $250 million of cash on hand at year-end 2016 No debt maturities until 2022 $1.2 OKS Adjusted EBITDA Growth ($ in Billions) $1.3 $1.3 $1.6 $1.6 $ G* 4.8x Adjusted EBITDA Growth OKS GAAP Debt-to-EBITDA Ratio 4.5x 4.7x 4.4x 4.2x * 2016G** GAAP Debt-to-EBITDA Ratio Page 29 *As of June 30, 2016 ** Expected ratio (or less) by late 2016

30 TOTAL SHAREHOLDER RETURN ONEOK AND ONEOK PARTNERS PROVEN LONG-TERM VALUE Long-term investors have experienced high returns from both ONEOK and ONEOK Partners 10-year returns for both investments outperformed the S&P 500 Index Year-to-date 2016 returns outperformed the S&P 500 and Alerian MLP Indexes 375% 215% 100% 105% 75% 80% 130% 5% 10% 40% 10% 30% YTD 5-year 10-year YTD 5-year 10-year ONEOK S&P 500 Index ONEOK Partners Alerian MLP Index Note: Total return as of June 30, Page 30

31 $ in Millions ONEOK PARTNERS EARNINGS ABILITY TO GROW DURING CHALLENGING ENVIRONMENTS Increased fee-based business model and infrastructure investments allow ONEOK Partners to grow earnings Q vs. Q2 2014: Net income and adjusted EBITDA: more than 20 percent increase Distributable cash flow: 35 percent increase $400 $300 $200 $100 $0 Q2 '14 Q3 '14* Q4 '14 Q1 '15 Q2 '15 Q3 '15 Q4 '15* Q1 '16 Q2 '16 Net Income Adjusted EBITDA DCF Page 31 *Third-quarter 2014 and fourth-quarter 2015 net income include noncash impairment charges of $76.4 million and $264.3 million, respectively, primarily related to investments in the coal-bed methane area of the Powder River Basin. Note: Reconciliations to relevant GAAP measures are include on pages

32 Page 32 KEY INVESTMENT CONSIDERATIONS PREMIER ENERGY COMPANIES ONEOK Stable cash flow Cash flow underpinned by investment-grade MLP with fee-based business model GP and LP distributions from ONEOK Partners drive significant cash flow generation and growth Prudent financial practices results in financial strength and flexibility ONEOK Partners Stable cash flow Primarily fee-based, nondiscretionary services Prudent financial practices: proactively manage commodity risk Strong balance sheet and financial flexibility: maintain investment-grade credit ratings with ample liquidity to support capital-growth projects Strategic, integrated assets connecting prolific supply basins and key markets create opportunities Nondiscretionary services to producers, processors and customers NGL infrastructure to support expected increased ethane demand beginning in 2017 Natural gas infrastructure to supply growing natural gas exports to Mexico Focused on creating value for both customers and investors Demonstrated financial discipline Commitment to investment-grade credit ratings at ONEOK Partners Disciplined growth Aligning capital-growth projects with producer customer needs as a result of lower commodity prices Safe, reliable and environmentally responsible operator Proven track record and commitment

33 Page 33 APPENDIX

34 NATURAL GAS GATHERING AND PROCESSING

35 NATURAL GAS GATHERING AND PROCESSING 2015 AVERAGE VOLUMES Gathered Volumes (Mmcf/d) Processed Volumes (Mmcf/d) 950 1,000 Region First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter Rocky Mountain Mid- Continent Total 1,448 1,533 1,485 1,628 1,265 1,275 1,223 1,359 Page 35

36 Percent Flared WILLISTON BASIN INCREASED GAS CAPTURE AND VOLUME BACKLOG BENEFITS OKS Increased natural gas capture results in increased NGL and natural gas value uplift More than 89% of North Dakota s natural gas production was captured in July 2016 North Dakota Industrial Commission (NDIC) policy targets: Increase natural gas capture to: 85% by Nov. 2016; 88% by Nov. 2018; and 91% by Nov July statewide flaring was approximately 180 MMcf/d, with approximately MMcf/d estimated to be on ONEOK Partners dedicated acreage Producer customers are more incentivized to increase natural gas capture rates to maximize the value of wells drilled 40% 35% North Dakota Natural Gas Produced and Flared 1,800 1,600 30% 25% 20% 15% 1,400 1,200 1, MMcf/d Produced 10% 400 5% 200 0% Page 36 Source: NDIC Department of Mineral Resources Gas Produced Percent of Gas Flared

37 Gathered Volume MMcfd WILLISTON BASIN VOLUME UPDATE* Natural gas gathered volumes expected to increase in 2016 Higher natural gas capture percentage (reduced flaring) as a result of pipelines, compression, processing plants placed in-service in late 2015 and the Bear Creek processing plant completed in August 2016 New well connects supported by sizable backlog of approximately 350 drilled but uncompleted wells (DUCs) on OKS acreage Natural declines to existing production more than offset by new volume Page Gathered Volume Exit Rate Flared Volumes Available for Capture Natural Declines 2016 Gathered Volume Exit Rate without Incremental Well Connections 2016 Annual Average Gathered Volume without New Wells * Theoretical slide showing flaring, decline and gathered volume assumptions Previous 2016 Annual Average Gathered Volume without New Wells New Wells (Drilled & DUCs) 2016 Guidance Average Gathered Volume 740 MMcfd

38 NATURAL GAS GATHERING AND PROCESSING COMMODITY PRICE RISK MITIGATION Six Months Ending December 31, 2016 Commodity Volumes Hedged Average Price Percent Hedged Natural Gas* (MMBtu/d) 79,100 $2.81 / MMBtu 93% Condensate (bpd) 1,800 $58.68 / Bbl 86% Natural Gas Liquids** (bpd) 8,800 $0.48 / gallon 82% Year Ending December 31, 2017*** Commodity Volumes Hedged Average Price Percent Hedged Natural Gas* (MMBtu/d) 73,100 $2.66 / MMBtu 74% Condensate (bpd) 1,800 $44.88 / Bbl 74% Natural Gas Liquids** (bpd) 8,000 $0.51 / gallon 67% Page 38 * Natural gas prices represent a combination of hedges at various basis locations **NGLs hedged reflect propane, normal butane, iso-butane and natural gasoline only. The ethane component of the equity NGL volume is not hedged and not expected to be material to ONEOK Partners results of operations *** As of June 30, 2016

39 NATURAL GAS GATHERING AND PROCESSING COMMODITY PRICE SENSITIVITIES 2016 Commodity Price Sensitivity After Hedging Commodity Sensitivity Earnings Impact* ($ in Millions) Natural Gas $0.10 / MMBtu $0.1 Natural gas liquids $0.01 / gallon $0.3 Crude Oil $1.00 / barrel $ Commodity Price Sensitivity After Hedging Commodity Sensitivity Earnings Impact** ($ in Millions) Natural Gas $0.10 / MMBtu $0.9 Natural gas liquids $0.01 / gallon $1.0 Crude Oil $1.00 / barrel $0.4 Page 39 *Six-month forward looking sensitivities net of hedges in place **12-month forward looking sensitivities net of hedges in place

40 NON-GAAP RECONCILIATIONS ONEOK

41 NON-GAAP RECONCILIATIONS ONEOK, INC. ONEOK has disclosed in this presentation anticipated cash flow available for dividends, free cash flow and dividend coverage ratio, all amounts that are non-gaap financial measures. Management believes these measures provide useful information to investors as a measure of financial performance for comparison with peer companies; however, these calculations may vary from company to company, so the company s computations may not be comparable with those of other companies. Cash flow available for dividends is defined as cash distributions declared from ONEOK s ownership in ONEOK Partners adjusted for ONEOK s standalone interest expense, corporate expenses, excluding certain noncash items, payments related to released contracts from ONEOK s former energy services business, capital expenditures and equity compensation reimbursed by ONEOK Partners. Free cash flow is defined as cash flow available for dividends, computed as described, less ONEOK s dividends declared. Dividend coverage ratio is defined as cash flow available for dividends divided by the dividends declared for the period. These non-gaap measures should not be considered in isolation or as a substitute for net income, income from operations or other measures of financial performance determined in accordance with GAAP. These non-gaap financial measures exclude some, but not all, items that affect net income. Additionally, these calculations may not be comparable with similarly titled measures of other companies. Reconciliations of cash flow available for dividends and free cash flow to net income are included in the tables. Page 41

42 OKE FINANCIAL MEASURES CASH FLOW AVAILABLE FOR DIVIDENDS ($ in Millions) G Recurring cash flows: Distributions from ONEOK Partners declared $633 $735 ~ $790 Interest expense (69) (78) ~(105) Released contracts from the former energy services business 48 (34) ~(20) Cash income tax Corporate expenses, excluding certain noncash items (7) (7) ~(10) Equity compensation reimbursed by ONEOK Partners ~25 Cash flows from recurring activities ~680 Separation-related costs/ogs cash flow/debt reduction (6) - - Total cash flows ~680 Capital expenditures (9) (2) ~(5) Cash flow available for dividends ~675 Dividends declared (485) (510) ~(515) Free cash flow $136 $131 ~$160 Dividend coverage ratio 1.3x 1.3x ~1.3x Page 42

43 OKE NON-GAAP RECONCILIATION CASH FLOW AVAILABLE FOR DIVIDENDS AND FREE CASH FLOW ($ in Millions) G Net income attributable to ONEOK $314 $245 ~$360 Depreciation and amortization 15 2 ~5 Deferred income taxes ~200 Equity in earnings of ONEOK Partners (563) (464) ~(700) Distributions from ONEOK Partners declared ~790 Equity compensation reimbursed by ONEOK Partners ~25 Energy Services realized working capital 63 (39) ~(20) Other (4) 4 ~20 Total cash flows ~680 Capital expenditures (9) (2) ~(5) Cash flow available for dividends ~675 Dividends (485) (510) ~(515) Free cash flow $136 $131 ~$160 Page 43

44 NON-GAAP RECONCILIATIONS ONEOK PARTNERS

45 NON-GAAP RECONCILIATIONS ONEOK PARTNERS ONEOK Partners has disclosed in this presentation its historical and anticipated adjusted EBITDA, distributable cash flow (DCF) and cash distribution coverage ratio, which are non-gaap financial metrics, used to measure the partnership s financial performance and are defined as follows: Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, impairment charges, income taxes and allowance for equity funds used during construction and certain other noncash items; DCF is defined as adjusted EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, excluding noncash impairment charges, adjusted for cash distributions received and certain other items; and Cash distribution coverage ratio is defined as distributable cash flow to limited partners per limited partner unit divided by the distribution declared per limited partner unit for the period. The partnership believes the non-gaap financial measures described above are useful to investors because they are used by many companies in its industry to measure financial performance and are commonly employed by financial analysts and others to evaluate the financial performance of the partnership and to compare the financial performance of the partnership with the performance of other publicly traded partnerships within its industry. Adjusted EBITDA, DCF and cash distribution coverage ratio should not be considered alternatives to net income, earnings per unit or any other measure of financial performance presented in accordance with GAAP. These non-gaap financial measures exclude some, but not all, items that affect net income. Additionally, these calculations may not be comparable with similarly titled measures of other companies. Furthermore, these non-gaap measures should not be viewed as indicative of the actual amount of cash that is available for distributions or that is planned to be distributed for a given period nor do they equate to available cash as defined in the partnership agreement. Reconciliations of adjusted EBITDA and DCF are included in the tables. This presentation references forward-looking estimates of annual adjusted EBITDA and adjusted EBITDA investment multiples projected to be generated by capitalgrowth projects. A reconciliation of estimated adjusted EBITDA to GAAP net income is not provided because the GAAP net income generated by the individual capital-growth projects is not available without unreasonable efforts. Page 45

46 OKS NON-GAAP RECONCILIATIONS ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW ($ in Millions) G Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow Net Income $831 $888 $804 $911 $598 ~$1,120 Interest expense, net of capitalized interest ~370 Depreciation and amortization ~380 Impairment charges Income tax (benefit) expense ~11 Allowance for equity funds used during construction and other (3) (13) (31) (15) 8 ~(1) Adjusted EBITDA $1,242 $1,294 $ 1,258 $1,558 $1,565 ~$1,880 Interest expense, net of capitalized interest (223) (206) (237) (282) (339) ~(370) Maintenance capital (94) (102) (92) (127) (116) ~(140) Equity in net earnings from investments, net noncash impairment charges (127) (123) (111) (117) (125) ~(135) Distributions received from unconsolidated affiliates ~160 Distributions to noncontrolling interest and other (8) (11) (6) (2) (5) ~(5) Distributable cash flow $946 $1,008 $ 949 $1,169 $1,136 ~$1,390 Page 46

47 OKS NON-GAAP RECONCILIATIONS ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW ($ in Millions) Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow Net Income $215 $167 $264 $147 $212 $230 $9 $256 $262 Interest expense, net of capitalized interest Depreciation and amortization Impairment charges Income tax (benefit) expense (1) 2 2 Allowance for equity funds used during construction and other (1) (1) (2) 7 1 (1) Adjusted EBITDA $361 $ 389 $415 $324 $387 $404 $450 $445 $456 Interest expense, net of capitalized interest (73) (70) (71) (81) (86) (87) (85) (93) (93) Maintenance capital (31) (29) (40) (32) (32) (21) (31) (22) (23) Equity in net earnings from investments, net noncash impairment charges (25) (24) (34) (31) (30) (32) (32) (33) (32) Distributions received from unconsolidated affiliates Distributions to noncontrolling interest and other (3) (5) 6 (2) (3) 3 (2) 4 (3) Distributable cash flow $272 $ 293 $306 $217 $277 $303 $339 $348 $367 Page 47

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